In the recovery of downhole hydrocarbons, it is useful to inject fluids or fluid slurries through the wellbore and into the hydrocarbon bearing formation to facilitate or otherwise treat the wellbore or the hydrocarbon bearing formation. Typically, accessing a hydrocarbon bearing formation begins with drilling a wellbore through at least one hydrocarbon bearing zone. After the well is drilled, the well is completed by inserting a casing into the wellbore, cementing the casing into place, and accessing the hydrocarbon bearing formation through the casing after which fluids may be injected into or removed from the formation. In some cases the casing is not cemented into the wellbore, in such situations annular packers may be used for zone isolation.
In addition to holding the casing in place the cement acts as an annular seal between the casing and the hydrocarbon formation as well as a seal longitudinally along the length of the casing between various hydrocarbon formations or hydrocarbon formation zones. Annular packers may also be used as longitudinal seal along the length of the casing between various, formations or hydrocarbon formation zones. Annular seals, whether by cement or by packers, along the length of the casing prevents fracturing fluid that is pumped down the wellbore from migrating out of the targeted zone. If such a targeted zone is not isolated, the fracturing fluid that is pumped down the wellbore, will flow into the annular area between the casing and the formation and travel along the exterior of the casing out of the targeted zone into areas that are not hydrocarbon bearing formations and perhaps even into other separate hydrocarbon bearing formations quickly overcoming the ability of the casing to transport the fluid into the formations and the ability of the pumps to supply the fluid at pressure sufficient to fracture the formation. Similarly, annular fluid flow between the wellbore and casing may result in reduced recovery of fluids, loss of treatment fluids, or infiltration of undesired materials into a targeted or untargeted zones.
Usually after a zone has been isolated, ports in the casing may be opened to allow for the injection of fluids or slurries into the well. The open ports may also facilitate the removal of fluids or slurries from the hydrocarbon bearing formation. It may be desirable that the ports may be selectively opened or closed. Typically the ports are installed in the well in a closed condition by use of sliding sleeves. Usually sliding sleeve valves comprise a sleeve having circumferential seals such as O-rings at the top and bottom edges thereof to seal against a wall of the casing. Thus, when the sleeve is positioned over a port, the sleeve substantially prevents fluid communication between the interior of the casing and the hydrocarbon bearing formation through the port. The port may be opened by moving the sliding sleeve so that the sliding sleeve is located above or below the port or at least aligning a port in the sliding sleeve with the port in the casing thereby allowing fluid flow into or out of the desired zone. In many instances the sliding sleeve is equipped with a seat in the interior of the sliding sleeve.
More specifically, a tubular assembly is put together on the rig floor prior to being lowered into the well bore. If the operator does not plan to cement the tubular assembly into the wellbore, annular zonal isolation packers will also be installed along the length of the tubular assembly. Typically a packer will be installed both above and below each port and spaced far enough apart to straddle a particular hydrocarbon bearing formation or a portion of a particular zone of a hydrocarbon bearing formation. In many instances a single packer may serve as the upper packer on one zone as well as the lower packer on an adjacent zone. The tubular assembly is then lowered into the wellbore so that a port is adjacent to the desired zone.
In order to open the sliding sleeve, the seat is sized such that when a ball, dart, or plug is pumped into the well the ball will land on the seat sealing the interior of the tubular at the seat against fluid flow past the seat. As fluid pressure is increased the ball then exerts force against the seat and thus the sliding sleeve thereby causing the sliding sleeve to open providing fluid access from the interior of the tubular to the exterior of the tubular. Usually the sliding sleeve having a seat with the smallest diameter is placed towards the bottom for toe of the well. Sliding sleeves having seats with increasingly larger diameters are placed in the wellbore such that the smallest diameter is at the bottom of the well while the largest diameter is towards the top of the well. By having sliding sleeves with seats with larger diameters towards the top of the well, the smaller diameter balls are able to pass through the upper sliding sleeves without actuating the sliding sleeves as they pass through them. Unfortunately there are limitations that are imposed upon the operator when completing the well using progressively larger sized seats and balls in conjunction with sliding valves such as an increasingly reduced diameter of the wellbore towards the toe of the well which in turn leads to either reduced production or milling out each of the progressively smaller valve seats. Additionally there is a limitation on the number of zones that may be accessed when using progressively larger size seats and balls.
A recurring problem in some fracturing operations has been premature screen-out. In many cases premature screen-out occurs when the proppant or sand bridges in the wellbore or casing or at a point where the flow velocity slows allowing the proppant to settle out of the transport fluid thereby preventing further fluid flow past the flow restriction. This can happen when the zone in a hydrocarbon formation stops taking a sufficient flow or volume of fluid to allow continued fracking of the zone. When a screen out occurs the fluid pressure needed to keep injecting proppant into a well exceeds the limitations of the tubulars, wellhead, or surface equipment thereby shutting down the frac operation. Additionally with fluid circulation in the wellbore lost it becomes practically impossible to pump an additional ball into the wellbore to open any valve above the flow restriction in order to continue the frac operation.
In one current method of dealing with the screen out the operator may draw or flow the well back along with the ball seated on the valve seat that corresponds to the screen out. By drawing the well and the last ball sent downhole the operator is able to attempt to remove the flow restriction in order to continue dropping balls and fracking the other zones above. If the screened out zone will not take any additional fluid, then when the operator attempts to pump fluid downhole the ball will reseal on the ball seat thus preventing further pump down. In such an event the current solution is to bring in coil tubing to intervene in the well in order to reestablish circulation. This can be a costly and time consuming process.